Transition pathways for a UK low carbon electricity system: Comparing scenarios and technology implications

Transcription

1 Transition pathways for a UK low carbon electricity system: Comparing scenarios and technology implications John Barton 1, Lloyd Davies 2, Ben Dooley 2, Timothy J Foxon 3, Stuart Galloway 4, Geoffrey P Hammond 5, Áine O Grady 5, Elizabeth Robertson 4,Murray Thompson 1 1 Centre for Renewable Energy Systems Technology (CREST), Loughborough University 2 Centre for Doctoral Training in Low Carbon Technologies, University of Leeds 3 Sustainability Research Institute, University of Leeds 4 Department of Electrical and Electronic Engineering, University of Strathclyde 5 Department of Mechanical Engineering, University of Bath Working Paper 213/5 16 December 213 Whole systems analysis for a UK more electric low carbon energy future 1

2 (RTP) is a UK Consortium of engineers, social scientists and policy analysts. The consortium is managed by Professor Geoffrey Hammond of the University of Bath and Professor Peter Pearson of Cardiff University (Co-Leaders). It includes research teams from nine British university institutions: the Universities of Bath, Cardiff, East Anglia, Leeds, Loughborough, Strathclyde, and Surrey, as well as Imperial College London and University College London. The RTP Project [ commenced in May 212 and is sponsored by the Engineering and Physical Sciences Research Council (EPSRC: Grant EP/K5316/1). It is a renewal and development of the earlier Transition Pathways (TP) project, which was initially established in 28 with the joint sponsorship of E.ON UK (the electricity generator) and the EPSRC. This project addressed the challenge of the so-called energy trilemma : the simultaneous delivery of low carbon, secure, and affordable energy services for the electricity sector. It developed and applied a variety of tools and approaches to analyse the technical feasibility, environmental impacts, economic consequences, and social acceptability of three transition pathways towards a UK low carbon electricity system. These pathways explore the roles of market, government and civil society actors in the governance of a low carbon energy transition. The research within the RTP Project seeks to explore further the constraints and opportunities in realising a low carbon UK energy sector, including those stemming from European developments. This project includes studies on the horizon scanning of innovative energy technologies over the period to 25, the feasibility of demand responses, uncertainties in economic analysis, the estimation of investment costs of the different pathways, and the implications of markets for investment decisions about energy technologies. Further work is being undertaken on conceptualising, mapping and analysing actor dynamics in the contemporary UK electricity sector, historical transitions and case studies, integrated energy networks modelling and evaluation, and whole systems energy and environmental appraisal of low carbon technologies and pathways. The consortium is also developing their initial work on branching points on pathways, in order to identify and explore other potential branching points on the core transition pathways. Follow us on 2

3 1. Introduction This paper compares the features and technology implications of a set of transition pathways for a UK low carbon electricity system to 25 with key scenarios produced by the UK government for meeting the UK s 8% greenhouse gas emissions reduction target by 25. This aims to provide an overview of how different framings and assumptions on demand reduction and generation mix can lead to significantly diverse low carbon futures (cf. Trutnevyte and Strachan, 213). More detailed discussion of the framing assumptions, demand side and generation and network implications of the transition pathways can be found in the papers by the project team (Hammond and Pearson, 213; Foxon, 213; Barton et al., 213; Barnacle et al., 213). Further considerations on the implications of the pathways for government, business and civil society in the context of recent UK energy policy developments is given in Foxon and Pearson (213). This paper aims to inform debate on the technical feasibility and social acceptability of the pathways and scenarios in relation to how decarbonisation of the UK electricity system can contribute to meeting the UK s energy and carbon reduction goals. However, the paper does not attempt to draw conclusions on the role or desirability of any particular technology or pathway. The UK has set itself on a transition to a low carbon economy and society, through the imposition of a goal of reducing the UK s greenhouse gas emissions by 8% by 25 and creation of an institutional framework relating to this goal, under the 28 Climate Change Act, which was passed with agreement of all major political parties. As generation of electricity constitutes a significant proportion of UK greenhouse gases, and technological options exist for the use of low carbon electricity for heating and transport as well as other energy services, much attention has been given to long-term scenarios and pathways for the reduction of carbon emissions from electricity. This type of pathway and scenario analysis is useful to enable actors to reflect on how current energy system decision making relates to the potential for achieving long-term energy and carbon reduction goals (Hughes and Strachan, 21; Hughes et al., 213). In order to do this, it is helpful to set out the features and technology implications of different pathways and scenarios. This paper does this by comparing a set of low carbon electricity pathways developed under a research project supported by Research Councils UK and the integrated energy company E.On UK 1 with official pathways developed by the UK Department for Energy and Climate Change (DECC) in HM Government s Carbon Plan (HM Government, 211). The low carbon Transition Pathways were developed by the authors and colleagues (Hammond and Pearson, 213; Foxon, 213) to examine the influence of different governance arrangements on potential pathways towards the 8% reduction target by 25. These pathways focus on the electricity sector, including the potential for increasing use of low carbon electricity for heating and transport. This follows the main scenarios developed by the Committee on Climate Change (CCC) and DECC, which also focussed on low carbon electrification as the key first step in the transformation of the UK energy system needed to meet the 8% target by However, unlike these scenarios, the Transition 1 The responsibility for the content of the pathways remains with the authors, and should not be taken to represent the views of any funder of the research. 2 Note that some researchers have argued that the UK needs to focus on reducing cumulative emissions and to achieve higher carbon reductions by 25, in order for the UK to take its fair share of the global reductions needed to meet a maximum 2 C temperature rise (Anderson and Bows, 212). 3

4 pathways were developed by starting from narrative storylines as to the potential consequences of different governance framings, drawing on interviews and workshops with stakeholders 3 and analysis of historical analogies (Arapostathis et al., 213). An iterative process of technical elaboration between social science and engineering researchers, informed by energy system modelling (Barton et al., 213; Barnacle et al., 213), was then followed to produce a quantification of the narrative for each pathway, as described in Foxon (213). This provides a way of examining the potential influence of qualitative social and institutional changes on the development of low carbon pathways, as well as providing a basis for more detailed technical and economic analyses of the pathways. However, it is important to compare the final quantified pathways with the main pathways developed by DECC. The paper is structured as follows. Sections 2 and 3 review the demand and generation projections for the low carbon transition pathways. Section 4 reviews the future scenarios in the UK Government s Carbon Plan. Section 5 provides a comparison of the pathways and scenarios. Section 6 examines technology implications of the pathways and scenarios. Section 7 assesses the greenhouse gas emissions projections for the transition pathways, before conclusions in section 8. 3 See website for reports and presentations from project workshops. 4

5 2. Low Carbon Transition Pathways demand projections The Transitions Pathways study approaches pathways from a governance perspective, and technology scenarios are produced under those perspectives. Foxon (213) describes three pathways, based on different dominant governance framings: 1) The Market Rules pathway is based on governance system similar to that of today, with a liberalised and privatised electricity and gas sector. Under this pathway, the dominant logic is that of the market: the best way to achieve the objectives is for government to set general high-level policy targets and the actors in this case primarily large energy companies deliver these. 2) The Central Coordination pathway is a world in which the government comes to the conclusion that meeting security of supply, affordability and emissions objectives will require direct intervention. This involves a government agency forming supply contracts for different low-carbon technology types to develop areas which are of importance to both the UK grid and in the strategic interest of the UK economy. In addition, public/private partnerships develop technology. This leads to strong advances in marine renewables, Carbon Capture and Storage (CCS) and electric vehicles. On the demand side, incentives are provided for household energy efficiency, although electrification of heating and transport drive up electricity demand. 3) The Thousand Flowers pathway envisages a low-carbon transition which is led by civil society. This bottom-up approach focuses on decentralised solutions to energy problems and has at its heart a society which is aware and informed on environmental themes and takes a proactive approach. Energy service companies (ESCOs) also emerge, which have incentives more aligned with energy efficiency improvements which aids the transition to a low-carbon economy. In these pathways, actors move towards achieving the 8% carbon emissions reduction target by 25, though the extent to which the resulting emissions reductions in the electricity sector contribute to meeting this target depends on projections of the effectiveness of these technologies achieving reductions, particularly when life cycle impacts are included (see Hammond et al., 213). The starting point for the quantification of these pathways is the projection of annual electricity demand by sector from 21 to 25. This is shown in Figures

6 Figure 2.1. Annual electricity demand (TWh) in Market Rules pathway (based on Barton et al. (213)) Figure 2.2. Annual electricity demand (TWh) in Central Co-ordination pathway (based on Barton et al. (213)) 6

7 Figure 2.3. Annual electricity demand (TWh) in Thousand Flowers pathway (based on Barton et al. (213)) In the Market Rules pathway, annual electricity demand rises from 337 TWh in 21 to 512 TWh in 25, due to increasing use of electricity for industry, commercial, transport and domestic space heating and hot water. This means that the electricity system needs to provide 5% more output by 25 than it currently does, requiring significant expansion of low-carbon generation beyond just replacing existing capacity. In the Central Co-ordination pathway, annual electricity demand rises from 337 TWh in 21 to 41 TWh in 25. This pathway sees electricity demand rising and then levelling off from 23 onwards, due to increasing use of electricity for transport and domestic space heating and hot water, but with higher rates of energy efficiency improvements in the domestic sector, and a smaller, highly efficient industrial sector with lower levels of output. This would imply that some energy-intensive UK production has moved to other countries, increasing the UK consumption of goods produced abroad, implying that UK carbon emissions calculated on a consumption basis would continue to diverge from those on a production basis (see Barrett et al., 213). In the Thousand Flowers pathway, annual electricity demand falls from 337 TWh in 21 to 31 TWh in 25. Despite similar levels of electrification of transport to the other pathways, electricity demand falls due to even higher rates of energy efficiency improvements in the domestic and commercial sectors, and a small, highly efficient industrial sector with low levels of output. In this pathway, a large proportion of domestic space heating and hot water demand is met by renewable (biogas) community-scale and micro- CHP systems rather than electric heating systems, helping to reduce electricity demand. In addition, the power generated by these local scale CHP systems replaces a significant proportion of centralised electricity supply, as discussed below. 7

8 Note that in all pathways, a significant amount of energy is used in industry and commerce for space heating and water heating. The provision of this heat is mostly via the same technologies as in the domestic sector of each pathway but often on a larger scale. Thus in the Market Rules and Central Coordination pathways, an increasing amount of electricity is used in heat pumps in the industrial and commercial sectors, as shown in Table 2.1. Pathway Market Rules Central Coordination Thousand Flowers Year Total Electricity for Heat & Hot Water (TWh) Domestic Electricity for Heat & Hot Water (TWh) Industrial & Commercial Electricity for Heat & Hot Water (TWh) Table 2.1. Electricity used for space heating and hot water in domestic, industry and commerce sectors Thus, the increased demand for electricity for heating and hot water in the Market Rules and Central Coordination pathways, in addition to the additional demand due to electrification of transport, leads to a significant increase in total final electricity demand in these pathways. On the contrary, in the Thousand Flowers pathway, the total final electricity demand remains stable up to 25, as the increase in transport electricity demand is offset by reductions in demand to energy efficiency improvements, and there is no increase in electricity demand for heating and hot water, due to the expansion of community-scale renewable CHP. 8

9 3. Low Carbon Transition Pathways supply projections In the Transition Pathways study, these demand projections for the three pathways are met by rising levels of low carbon electricity generation, including different generation capacities of renewables, nuclear power and coal and gas with carbon capture and storage (CCS or sequestration), operating at different capacity factors. The generation capacity for each pathway from 21 to 25 is shown in Figures Figure 3.1. Generation capacity in Market Rules pathway (based on Barnacle et al. (213)) Figure 3.2. Generation capacity in Central Co-ordination pathway (based on Barnacle et al. (213)) 9

10 Figure 3.3. Generation capacity in Thousand Flowers pathway (based on Barnacle et al. (213)) Timelines In 21, the UK had around 95 GW of electricity generation capacity, including 29 GW of coal and dual fuel generation, 33 GW of gas-fired generation, 11 GW of nuclear power, 9 GW of renewable generation and 6 GW of combined heat and power (CHP) cogeneration. In the Market Rules pathway, investment occurs in all three main types of low-carbon generation, driven by a high carbon price. Significant amounts of capacity come on stream in the 22s, so that, by 23, there are 21 GW of coal and gas with carbon capture and storage (CCS), 15 GW of nuclear power and 47 GW of renewables (47 GW), giving a total capacity of 13 GW by 23. Subsequent deployment leads to further increases in capacity in order to meet rising electricity demand, particularly from industry and electrification of heating and transport, over following decades. By 25, this results in a total of 168 GW of capacity, including 44 GW of coal and gas generation with CCS, 26 GW of nuclear power, and 8 GW of renewable capacity, principally onshore (23 GW) and offshore (3 GW) wind, tidal power (12 GW) and renewable CHP (9 GW). This provides a total supply of 539 TWh in 25. In the Central Co-ordination pathway, there is a similar investment in all types of low-carbon generation capacity in the 22s, co-ordinated by a Strategic Energy Agency. This leads to a total of 122 GW in 23, though with high levels of nuclear power (22 GW), and slightly lower levels of coal and gas with CCS (18 GW) and renewables (43 GW). Despite the subsequent levelling off of demand in this pathway, further deployment needs to an increase in capacity to a total of 151 GW by 25, of which the largest single contribution comes from nuclear power (3 GW). There is a similar contribution (3 GW) coal and gas fired generation with CCS, but this operates at a lower capacity factor (36%), as it partly provides back-up to intermittent renewables. There is a total of 65 GW of renewable generation, of which the largest contributions are from onshore (21 GW) and offshore (17 GW) wind. This provides a total supply of 427 TWh in 25. 1

11 In the Thousand Flowers pathway, action by community groups and local and regional energy service companies (ESCos) leads to a significant expansion of community- and microscale renewable CHP installed from 22 onwards, reaching a total of 37 GW by 23. The total capacity of 149 GW by 25 is similar to that of Central Co-ordination, but the majority of this is made up of renewable generation (112 GW). As noted above, a significant proportion of demand is met by local scale renewables, reducing the need for centralised electricity supply. The largest single contribution to generation comes from renewable (biogas) community-scale and micro- CHP systems (44 GW), followed by onshore wind (21 GW), solar PV (16 GW) and offshore wind (8 GW). There is some investment in other low carbon generation technologies in earlier periods, resulting in 22 GW of coal and gas with CCS and 5 GW of nuclear capacity by 25. This provides a total supply of 313 TWh in 25. Summary Hence, in all three pathways, generation capacity increases substantially by 25, but the generation mixes are markedly different between the pathways. In the Market Rules and Central Co-ordination pathways, coal and gas fired generation with CCS, nuclear power and onshore and offshore wind all make significant contributions to capacity, required to provide the output to meet the rising electricity demand in these pathways. In the civil society-led Thousand Flowers pathway, there is much less investment in these large centralised generation options, and instead, a significant expansion of more local generation from renewable (biogas) community-scale and micro- CHP, onshore wind and solar PV. 11

12 4. UK Carbon Plan pathways The Carbon Plan (HM Government, 211) is the most recent statement by the UK Government of the range of measures and incentives that it has already or intends to put in place, to ensure that the UK is on track to meet the target of reducing its greenhouse gas emissions by 8% by 25, as required by the Climate Change Act (28). A foreword to the Carbon Plan, signed by the Prime Minister and the Deputy Prime Minister, states that Even in these tough times, moving to a low carbon economy is the right thing to do, for our economy, our society and the planet (HM Government, 211, Foreword). Though the Plan addresses the whole of the UK economy, the main measures relate to the energy sector. The Plan also seeks to address the so-called trilemma of energy policy: to make the transition to a low carbon economy, whilst maintaining energy security and minimising costs to consumers, particularly those in poorer households (HM Government, 211, p.3). The main focus of the Carbon Plan is the additional measures needed to meet the fourth carbon budget, covering , which was set into law 12 years in advance, as required under the Climate Change Act, following the recommendation for the budget level by the Committee on Climate Change (CCC, 211). This requires UK greenhouse gas emissions to be reduced by 5% below 199 levels by , an additional 29% below 29 levels. The main measures include the Green Deal, a scheme for households to finance energy efficiency improvements at no upfront cost which began operating in January 213 (DECC, 21b), and the Electricity Market Reform programme for stimulating investment in low carbon electricity generation (DECC, 212a). The latter is embodied in the Energy Bill going through the UK Parliament in , though the first negotiations are already underway with energy company EDF to provide a guaranteed strike price for the first two new nuclear power stations, planned to be built at Hinkley Point, under the new Contract for Difference Feed-in Tariffs, a key part of the reforms 4. As noted, the key challenge for the UK government will be to balance these incentives for investment in low carbon generation, including renewables, nuclear and demonstration CCS projects with ensuring energy security and maintaining affordability of energy to consumers. This is linked to the challenge of ensuring sufficient progress to keep the UK on track to meet its 8% reduction target by 25, whilst limiting the additional costs both to the Treasury and those costs passed on to consumers in the short- to medium-term. This is very challenging in the face of a number of uncertainties, including future levels of energy service demand - which depend on uptake of energy efficiency measures and end-use technologies and levels of economic activity - and the technical and economic feasibility and acceptability of a range of low carbon energy options, particularly for electricity generation. To this end, the Carbon Plan explores four 25 futures, which are potential pathways or scenarios for meeting the 8% reduction target by 25. The first is based on a core simulation run of the MARKAL cost-optimising energy system model and the three other scenarios were developed using the DECC 25 calculator tool. This section sets out the electricity demand and supply projections in these scenarios and in the next section compare these to those of 4 On 21 October 213, the UK Government announced an agreement with French energy company EDF and its Chinese energy company partners to provide support for the building of a new 2 reactor 3.2 GW nuclear power station at Hinkley Point in South-West England, guaranteeing an index-linked price of at least 89.5 for each MWh generated for 35 years, 12

13 the transition pathways to 25. The projected electricity demand and generation capacity of the Carbon Plan pathways are shown in Figures Core MARKAL scenario Overall trends In the core MARKAL scenario, the cost-optimised parameterisation includes a sharp reduction in overall per capita energy demand, thanks to end-use energy efficiency improvements and switch to more efficient electric heating and vehicles. However, as a result, electricity demand rises by 46% to 433 TWh by 25 (see Figure 4.1), and almost all of this needs to be met by low carbon generation sources. Under the core MARKAL (updated MARKAL 3.26) scenario, by 25, capacity rises to a total of 112 GW (see figure 4.2), including 31 GW of nuclear, 25 GW of coal, biomass and gas generation with carbon sequestration, and 49 GW of renewable generation, with 7.5 GW of standby/peaking gas capacity, providing a total of 56 TWh of supply, of which 89 TWh is exported. This is driven by the expansion of the use of low carbon electricity in transport for electric vehicles and in heating via air- and ground-source heat pumps, as well as for domestic and industrial power and lighting services. Note that this scenario implies an overall increase in the average capacity factor of electricity generation from 43% in 21 to 58% in 25, thanks partly due to a projected capacity factor of 8% for new nuclear power stations Transport Domestic Commercial Industrial Figure 4.1. Annual electricity demand (TWh) in core MARKAL scenario (based on HM Government, 211) 13

14 Standby/ Peaking Gas Tidal Range Tidal Stream Wave Hydro Offshore Wind Onshore Wind Nuclear Gas CCGT CCS Solid HC CCS Post Solid HC CCS Pre Gas CCGT Oil Biomass Coal Figure 4.2. Generation capacity (GW) in core MARKAL scenario (based on HM Government, 211) Timeline In this scenario, there is a rapid expansion of onshore and offshore wind to 23 to replace declining coal capacity, though there remains significant gas CCGT capacity to 23. Nuclear power capacity expands rapidly after 23 to become three times as large as current nuclear capacity by 25. There is a slower expansion of solid hydrocarbons (roughly equal coal and biomass) with pre- and post-combustion CCS, and gas (roughly equal natural gas and biogas) CCGT with CCS after 23. There are significant contributions after 23 from offshore renewables, including tidal range, tidal stream and wave power, and a maintained capacity of offshore wind, though the amount of onshore wind reduces (see Table 4.1) Description Coal GW plant Biomass MW Plant Gas CCGT GW plant Solid HC CCS Pre GW locations Comb Solid HC CCS Post GW locations Comb Gas CCGT with CCS GW locations Nuclear GW plant Wind (onshore) MW Turbines Wind (offshore) MW Turbines Hydro MW Sites Wave ,41 6, MW Machines Tidal Stream Approximate number of 1.2MW Seagen devices Tidal Range Approximate number of 24 MW tidal range sites Standby/Peak Gas GW Plant 14

15 Annual electricity demand (TWh) Table 4.1. Number of plants required to meet installed capacity in core MARKAL scenario 4.2. Higher renewables, more energy efficiency future Overall trends In this scenario there are significant improvements in energy efficiency in homes and industry. However, there is also a high degree of electrification in transportation, space heating and hot water, and industry. This leads to a 45 per cent increase in electricitydemand from 21 to a value of 49 TWh in 25 (Figure 4.3) Industry Commercial Domestic lighting, appliances and cooking Domestic space heating and hot water Transport Fuel industries Agriculture District heating Figure 4.3. Annual electricity demand (TWh) in Higher renewables, more energy efficiency future (based on HM Government, 211) To meet this growth, generating capacity including balancing generation increases by 161% over the same period to reach 21 GW (Figure 4.4). This is the highest electricity generation capacity of all the scenarios. This growth outstrips that of demand primarily due to the dominance of renewables on the system, which accounts for 52% of capacity including backup in 25. Of the renewables in this scenario, most of the capacity is in onshore and offshore wind, with 28.4 and 54 GW in 25, respectively. With their comparatively low load factors of 3% for onshore wind and 45% for offshore wind, an increased capacity is required to meet demand. In addition, due to the intermittent nature of these renewables, the scenario requires a significant proportion of the capacity to be accounted for by generation capacity whose function is grid balancing: 24.4 GW of gas, 2 GW of storage and 3 GW of interconnection. 15

16 Generation capacity (GW) CHP - Other Fuels CHP - Renewable Fuels CHP - Natural Gas Pumped Storage Imports Solar Tidal Wave Biomass Hydro Wind (offshore) Wind (onshore) Nuclear Gas CCGT with CCS Coal CCS Oil Gas OCGT Gas CCGT Coal Figure 4.4. Generation capacity (GW) in Higher renewables, more energy efficiency future (based on HM Government, 211) Timeline To 22, growth in wind power is almost entirely responsible for offsetting the decline in coal and nuclear power as the current fleet of these generators are retired. To 23, new nuclear power and commercial CCS plants begin to emerge, but closures continue to hold down the proportion of nuclear on the grid. Over the same period, offshore wind continues to grow strongly, adding 16 GW to the system, compared to 1 GW of onshore wind. Between 23 and 25 growth in wind falls to zero, while CCS and nuclear continue to expand. Other renewables, notably, solar PV, wave and tidal, are deployed in higher levels between 24 and Higher nuclear, less energy efficiency future Overall trends This scenario sees a very limited effort to reduce energy demand across the economy through behaviour change or energy efficiency measures. Large-scale electrification of transport and heating drives increases in electricity demand, which increases by 6% (Figure 4.5). Of the four DECC scenarios, the electricity demand in 25 is the highest at 555 TWh. However, electricity generation capacity growth grows by only 51% to reach 123 GW (Figure 4.6). This growth rate is less than the increase in demand due to the high penetration of nuclear generation in 25 which has a high capacity factor of 8%. This deployment of nuclear increases the average capacity factor of generation on the grid. There is small but significant role played by storage, interconnection and gas power in 25, with 11.3 GW of backup gas capacity, 4 GW of storage and 1 GW of interconnection. 16

17 Generation capacity (GW) Annual electricity demand (TWh) Industry Domestic lighting, appliances and cooking Transport Agriculture Commercial Domestic space heating and hot water Fuel industries District heating Figure 4.5. Annual electricity demand (TWh) in Higher nuclear, less energy efficiency future (based on HM Government, 211) CHP - Other Fuels CHP - Renewable Fuels CHP - Natural Gas Pumped Storage Imports Solar Tidal Wave Biomass Hydro Wind (offshore) Wind (onshore) Nuclear Gas CCGT with CCS Coal CCS Oil Gas OCGT Gas CCGT Coal Figure 4.6. Generation capacity (GW) in Higher nuclear, less energy efficiency future (based on HM Government, 211) Timeline Due to the long lead times for nuclear, significant new rollout does not begin until from 225. Although by 22, 3.2 GW of new plant is added to the system, the closure of 6.4 GW of legacy plant in the previous 1 years results in a minimum penetration of nuclear power. 17

18 Annual electricity demand (TWh) At this stage 1.5 GW of demonstration CCS plant has been built but no commercial deployment takes place. New nuclear build rates are ramped so that beyond 225 almost 2.5 GW of new plant is built per year, a rate that is maintained to the end of the scenario, by which time 75 GW of nuclear are installed. However, this delay, along with the closure of coal plants and growing electricity demand requires non-nuclear capacity to fill the gap. Up to 22 new gas capacity is built, and the cheapest renewable source wind power plays an important short-term role. Onshore wind is added at a steady and continuous rate up to 225 when its deployment peaks, and capacity declines to 25. Offshore wind follows a similar pattern, peaking shortly after 225, then gently declining as nuclear capacity expands. By 25 the generation system is dominated by nuclear power, which accounts for 61% of capacity including backup Higher CCS, more bioenergy future Overall trends In this scenario, there is medium level of energy demand of investment in energy efficiency. However, there is only limited electrification of transportation which results in minimal growth in annual electricity demand to 25 to 461 TWh, a 34% increase on 21 levels (Figure 4.7). In 25 this scenario has a relatively diverse generation mix, with 35% of capacity coming from CCS, 29% from renewables, and 19% from nuclear. In this scenario storage, interconnection and gas backup plays a very limited role in grid balancing due to the ability in the DECC 25 calculator for CCS and nuclear to provide increased output to compensate for intermittent output from renewable generators. The generation capacity in this scenario is the lowest of the four DECC pathways, increasing to 11 GW in Industry Domestic lighting, appliances and cooking Transport Agriculture Commercial Domestic space heating and hot water Fuel industries District heating Figure 4.7. Annual electricity demand (TWh) in Higher CCS, more bioenergy future (based on HM Government, 211) 18

19 Generation capacity (GW) CHP - Other Fuels CHP - Renewable Fuels CHP - Natural Gas Pumped Storage Imports Solar Tidal Wave Biomass Hydro Wind (offshore) Wind (onshore) Nuclear Gas CCGT with CCS Coal CCS Oil Gas OCGT Gas CCGT Coal Figure 4.8. Generation capacity (GW) in Higher CCS, more bioenergy future (based on HM Government, 211). Note: By 25, 77% of coal CCS is co-fired biomass, and 15% of gas CCGT with CCS is biogas. Timeline As in the other scenarios, electricity demand declines slightly to 215. Consistent with the reduced electricity demand, generation capacity decreases to 215, although it subsequently increases through to 25. The capacity added to 23 is primarily from the renewables, which offsets the decline of coal as gas stays roughly flat. Over the same period, new nuclear build compensates for legacy plant closures. From 23 onwards large deployment of CCS commences, with new build rates increasing to around 1.5 GW per year. Over the same time gas declines rapidly to zero in 245, while nuclear begins to accumulate on the system and the proportion of capacity accounted for by nuclear increases. This leads to a static capacity from 225 to 245. Between 245 and 25 the expansion of CCS drives generation capacity up to its highest level over the modelled period. It is important to note that the co-firing of biomass with coal CCS and biogas with gas CCS implies the potential for net negative CO 2 emissions in this scenario. The high capacity factor of CCS 85% means that generation capacity of this type can have a large impact on generation. While electricity generation matches electricity demand plus losses for most of the modelled period, the large increases in capacity from 245 to 25 result in excess electricity production and net exports of 14.7 TWh. Summary The DECC scenarios all show significant increases in capacity of one or more of the key low carbon generation technologies needed to meet increases in electricity demand. The Core MARKAL scenario has the most balanced mix of the three main low carbon technologies, with 31 GW of nuclear, 25 GW of coal, biomass and gas generation with CCS, and 49 GW of 19

20 renewable generation by 25. This mix, together with increases in average capacity factors, means a relatively modest increase in overall capacity to 112 GW by 25. As this scenario is produced using the MARKAL model to optimise the pathway to meeting the carbon budgets and the 8% reduction target by 25, this assumes that investment decisions are made in a cost optimal way. Whilst this provides a useful benchmark for comparison with other pathways, it must be remembered that technological and institutional path dependencies and bounded rationality of firms and individuals mean that optimal decisions are unlikely to always be made. Hence, the three other scenarios were designed using the 25 Calculator to examine options in which investment is focussed more on one of the three technology areas. In the higher renewables, high energy efficiency scenario, electricity demand rises, despite improvements in energy efficiency for homes and industry, due to increases in the use of electricity for transport, home heating and industry. This requires more than doubling of electricity capacity to 21 GW by 21, with the largest share coming from 54 GW of offshore wind, and high levels of back-up gas generation, storage and interconnection. In the higher nuclear, less energy efficiency scenario, higher levels of electricity demand are met with a comparatively lower installed capacity of 123 GW (including storage and interconnectors). However, this requires 75 GW of nuclear power to be installed by 25, which is assumed to operate at a capacity factor of 8%. In the higher CCS, more bioenergy scenario, there is less focus on electrification of home heating and again high capacity factors are assumed for nuclear and thermal generation with CCS. This leads to a more modest generating capacity of 1 GW in 25, including 35 GW with CCS. The 8% reduction target in 25 is met thanks to negative emissions resulting from power generation of biomass and biogas in thermal plants with CCS. The following sections compare in more detail the characteristics and assumptions of the transition pathways and DECC scenarios, in order to understand better what would be needed to realise any of these pathways. 2

21 5. Scenario comparisons This section begins by comparing the assumptions on capacity factors between the pathways and scenarios since these make significant differences to the levels of installed capacity needed. It goes on to compare the annual electricity demand, capacity and output across the scenarios in 25, before examining the implications for particular technologies in the next section Capacity factors The assumed capacity factors for each of the generation scenarios are important because they affect the amount (GW) of capacity that is necessary for general grid operation, and influence the amount of demand-side management and backup requirements of the grid. A comparison of the maximum capacity factors for the DECC scenarios and Transition Pathways is shown in Table 5.1. DECC scenarios 5 Transition Pathways Coal 6% 48% Gas 7% 56% Oil 6% 13% CCS 85% 9% Nuclear 8% 61% Onshore wind 3% 29% Offshore wind 45% 43% Hydro 38% 37% Biomass 9% 61% Wave 23% 28% Tidal range 2-24% 24% Tidal stream 4% 24% Solar 1% 11% Table 5.1: Maximum capacity factors in 25 for different models. Transition pathways capacity factors are maximum values across the three pathways In the DECC calculator, capacity factors are fixed for any particular year for all technologies except biomass/coal. Most are also invariant over the modelled period, except nuclear, which increases from 6 per cent in 21 by 2 per cent per year to reach 8 per cent in 22, and offshore wind, which gradually increases from 35 per cent in 215 to 45 per cent 5 These compare to capacity factors in 21 for nuclear of 6% and offshore wind of 35%. Source: DECC, 212b 21

22 Load factor in 235. In contrast, in the Transition pathways study, capacity factors for the non-thermal generators wind, hydro, wave, tidal and solar are static from 21 to 25, but for thermal generation vary from year to year. Conventional fossil fuel thermal generation coal, gas and oil trend downwards to zero; coal generation is gone from the system by 235, and oil at the latest by 22. The most significant difference in these figures is for nuclear power. In 21, values from both DECC and the Transitions pathways study are in line with current values (Figure 5.1). However, in the DECC calculator, nuclear capacity factor increases to levels that have previously been achieved in the UK, but not maintained for extended periods. It is unclear how much capacity factors would increase for new build power stations, as the model favoured by EDF the European Pressurized Reactor (EPR) is not yet operational at any of the sites at which new build are being constructed. However, Areva (25) claims an availability factor of up to 92%, on average, during the entire service life of the plant. 9% 8% 7% 6% 5% 4% 3% 2% 1% % Figure 5.1: Load factor for nuclear power from 1996 to 211. Source: DECC, 212b How the capacity factor of gas should be viewed is not straightforward. A proportion of gas generation is, in most cases, needed to balance the grid in the case of a supply shock. Such a supply shock can occur when there is high electricity demand (e.g. in times of low external temperatures) and low output from renewables on the grid. The impact of this, and consequently the requirement for backup, clearly depends to some extent on penetration of renewables on the grid. However, in the DECC calculator, back-up generation makes no contribution to annual electricity generation figures. As a result, the capacity factors for gas in the DECC scenarios and the transition pathways, based on the calculated generation data, reduce to close to zero by 25. When the need for backup generation is included in capacity factor calculations, the capacity factors for gas power stations in the DECC scenarios move closer to those in the Transition Pathways study (Figure 5.2), but there are still considerable differences between the DECC scenarios and those of the Transitions Pathways study. This is 22

23 while the gas generation capacities in the models are broadly similar, at least until 23 (see Table 5.2). Pathway Renewables Nuclear CCS Market rules Central coordination Thousand flowers Table 5.2: Gas capacity (GW) in 23 for different scenarios 1% 9% 8% 7% 6% 5% 4% 3% 2% 1% % Scenario I Scenario II Scenario III Markal 3.26 Market rules Central coordination Thousand flowers Figure 5.2: Load factor for gas generation including backup generation in DECC scenarios 23

24 Annual electricity demand (TWh) 9% 8% 7% 6% 5% 4% 3% 2% 1% % Figure 5.3: Load factor for gas CCGTs from 1996 to 211 Source: DECC, 212b 5.2. Scenario differences The demand for electricity in 25 for all seven scenarios is compared in Figure 5.4. The Thousand Flowers scenario is the only one in which electricity demand decreases from 21 to 25. The one in which demand is the largest is the second of DECC s scenarios, which focuses on nuclear power and does not prioritise energy efficiency. The results from these scenarios suggest that in the absence of a motivated civil society which takes responsibility for climate change mitigation, electricity demand reductions are not likely, even with very high levels of energy efficiency as seen in DECC s higher renewables, higher energy efficiency pathway. However, this is not inconsistent with 8 per cent greenhouse gas emissions reductions by Figure 5.4: Electricity demand (TWh) in 25 under DECC scenarios (left) and three Transition Pathways scenarios (right) 24

25 Generation capacity (GW) The generation capacity for the different scenarios, including back-up gas capacity, storage and interconnection in the DECC scenarios, is shown in Figure 5.5. Although all except the Thousand Flowers scenario rely heavily on CCS, nuclear and wind, there is a diverse range of generation mixes. Due to the lower capacity factors of renewables, those with a large amount of this type of generation tend to have a higher generating capacity. All of the scenarios except the higher CCS scenario show a large increase in generation capacity by 25 on today s level of around 9 GW CHP - Renewable fuels Pumped storage Imports Other renewables Wind (offshore) Wind (onshore) Nuclear CCS Oil Gas Figure 5.5: Generation capacity (GW) for DECC scenarios and transition pathways in 25, including peaking gas, interconnection and pumped storage in DECC scenarios The annual UK electricity generation in 21 and 25 for the MARKAL scenario and Transition Pathways is shown in Figure 5.6. This shows that the total electricity generation in 25 for the Market Rules pathway is similar to that for the MARKAL scenario, though with a higher proportion of renewables. The total generation is lower in the Central Co-ordination pathway, and significantly lower in the Thousand Flowers pathway (to below the output in 21, despite the expansion of electric vehicles in this pathway). 25

26 Electricity generation (TWh) Unabated thermal Renewables CCS Nuclear Figure 5.6. Annual UK electricity generation (TWh) in 21 and 25 under DECC scenarios and Transition Pathways 26

27 6. Technology implications The above comparisons show that all these scenarios and pathways imply high levels of deployment of some or all low carbon generation technologies, as well as ranges of energy efficiency improvements. This section considers in more detail the implied deployment rates for some key technologies. This is done in reference to the deployment trajectory levels within the DECC 25 calculator, which range from level 1- little or no effort made, to level 4- extremely ambitious targets that push towards the technical or physical limits of what can be achieved (HM Government 21a) Nuclear The core MARKAL and higher nuclear, less energy efficiency scenarios, as well as the Market Rules and Central Co-ordination pathways, all imply a significant expansion of the UK s nuclear capacity from the current value of 11 GW from 23 onwards. The higher renewables, more energy efficiency and higher CCS, more bioenergy scenarios show a smaller increase in nuclear capacity. Only in the Thousand Flowers pathway, does nuclear play no significant role (in line with DECC trajectory level 1). Rising nuclear generation capacity reflects the UK government s belief that nuclear power has a role to play in the future UK energy mix alongside low carbon technologies and that energy companies should be given the option to invest in new nuclear build (DECC, 211). The minimum (level 1) trajectory implies that there is a change in government thinking and that nuclear is no longer seen as a favoured technology. The core MARKAL scenario assumes a deployment rate corresponding to level 1.7 in the DECC 25 calculator, which implies that 2.5 GW of nuclear capacity is in place by 22, with just under 1 GW of capacity added annually thereafter, leading to 31 GW installed capacity by 25. This is equivalent to 2 new nuclear power stations of capacity 1.5 GW coming on line every 3 years from 22 to 25. The DECC high nuclear, less energy efficiency scenario assumes a trajectory level of 2.7 resulting in a 2.5 GW/year build rate from 225, equivalent to 3 new power stations every 2 years, leading to a 75 GW installed capacity by 25. The Market Rules pathway implies a similar trajectory to the core MARKAL scenario, leading to 25 GW of capacity by 25, and the Central Co-ordination pathway implies a similar end-point of 3 GW capacity by 25, though with a more rapid build-up in earlier years of this pathway to reach 22 GW of installed capacity by 23. The installed capacity and annual build rates for all the scenarios are shown in Figures 6.1 and

28 Nuclear Build Rate, MW/Year Nuclear Power, GW Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS, more bioenergy Market Rules Central Coordination Thousand Flowers Figure 6.1. Installed capacity (GW) for nuclear power to 25 in the MARKAL, DECC and Transition Pathways Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS, more bioenergy Market Rules Central Coordination Thousand Flowers Figure 6.2. Annual build rates (MW/year) for nuclear power to 25 in the MARKAL, DECC and Transition Pathways (net of closures to 23) In order to meet the deployment levels seen in the pathways there would need to be clear support by both the public and government, with regulatory certainty regarding the acceptability of reactor design and market certainty giving operators confidence that they will see a return over the lifetime of the project. In order to incentivise deployment, the UK government has identified eight possible sites for new nuclear power stations, with one reactor at each site this could result in the addition of 1-14 GW capacity by 225 (DECC, 28

29 Carbon Capture & Storage, GW 211). It has provided support through the Contract for Difference feed-in tariff under the Electricity Market Reform (DECC, 212), as well as streamlining the design regulation and planning requirements. However, the high capital costs of new nuclear power stations, as well as continuing concerns amongst sections of the public over safety, waste management and nuclear proliferation, remain significant barriers to a large scale-up of nuclear power in the UK Carbon capture and storage Carbon capture and storage (CCS), or carbon sequestration, also plays a significant role in most of the scenarios and accounts for a similar percentage of the total generation in all the scenarios except the Thousand Flowers and the DECC High nuclear pathways. The core MARKAL scenario assumes a build rate corresponding to trajectory level 1.6, which implies that 1.7 GW of demonstration capacity is in place by 22, with 5 GW of commercial capacity by 23 and just under 1 GW added annually, leading to 25 GW of capacity with CCS by 25. In the high CCS, more bioenergy scenario, this increases to 1.5 GW per year added from 23, leading to an installed capacity of 4 GW by 25. In contrast, in the high nuclear, less energy efficiency scenario, no further CCS capacity is built after the initial 1.7 GW demonstration capacity. The Market Rules pathway is similar to the high CCS scenario, with 44 GW of capacity with CCS by 25, though with 21 GW of capacity already by 23. The Central Co-ordination pathway is similar to the core MARKAL scenario, with 3 GW of capacity with CCS by 25, though with 18 GW of capacity already by 23. The Thousand Flowers pathway also has 16 GW of capacity with CCS by 23, though this rises to only 21 GW by 25, as more distributed generation is favoured. The installed capacity and annual build rates for all the scenarios are shown in Figures 6.3 and Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS, more bioenergy Market Rules Central Coordination Thousand Flowers Figure 6.3. Installed capacity (GW) for carbon capture and storage (for coal and gas) to 25 in the MARKAL, DECC and Transition Pathways 29

30 CCS Build Rate, MW/Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS, more bioenergy Year Market Rules Central Coordination Thousand Flowers Figure 6.4. Annual build rates (MW/year) for carbon capture and storage (for coal and gas) to 25 in the MARKAL, DECC and Transition Pathways There is an energy penalty associated with CO 2 capture that reduces the overall efficiency of the power plant. In the DECC calculator, this is assumed to range initially from 13 to 27%, depending on the type of power plant, gas, pre-combustion solid or post-combustion solid. This energy penalty is assumed to reduce, as the efficiency of the capture process improves, to 12 to 16% from 22 (cf Gough et al., 212). Attention must also be given to the reduction of carbon emissions by installing CCS technology. The DECC calculator assumes that 9% of CO 2 emissions are captured, but research by the Transition Pathways team shows that, when life cycle effects are taken into account, this can reduce to a 7% capture rate over the life cycle (Hammond et al., 213). The UK government is currently working with industry to support the development of a cost-competitive CCS industry in the 22s, through a 1 billion commercialisation competition, support for R&D and innovation, and the electricity market reform programme, though only a small number of small-scale CO 2 capture demonstrations have so far been implemented (DECC, 211) Onshore wind In the core MARKAL scenario,.7 GW of onshore wind are added annually from 21 to 225, with.3 GW added annually thereafter. However, as turbines are only projected to have lifetimes of 2 years, this is below the replacement rate, and so the installed capacity peaks at 13 GW in 225, reducing to 6 GW by 25. As shown in Table 4.1, this corresponds to a maximum of over 4,7 turbines of size 2.5 MW, reducing to around 2,4 turbines by 25. Similar rates are seen in the high nuclear and high CCS scenarios, but in the Higher renewables scenario, the installation rate rises to 1.4 GW per year, leading total installed onshore wind capacity to rise to 28 GW by 23 and to be retained at that level to 25. A similar final level of deployment of 21 to 23 GW by 25 is seen in all three transition 3

31 Onshore Wind Build Rate, MW/Year Onshore Wind Power, GW pathways, though the deployment is more evenly timed, with only 14 to 15 GW of installed capacity by Analogous to Markal Year Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS, more bioenergy Market Rules Central Cordination or Thousand Flowers Figure 6.5. Installed capacity (GW) for onshore wind to 25 in the MARKAL, DECC and Transition Pathways Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS, more bioenergy Market Rules Central Coordination or Thousand Flowers Figure 6.6. Annual build rates (MW/year) for onshore wind to 25 in the MARKAL, DECC and Transition Pathways (net of closures) It is assumed that onshore wind will be present in the form of both large scale wind farms and smaller scale community wind projects (HM Government 21a). The key support 31

32 Offshore Wind Power, GW mechanisms for reaching the high deployment levels are the Renewables Obligation (to 217) and the Contract for Difference Feed-in Tariffs, which will be implemented from 214 (DECC, 212), though obtaining planning permission remains an issue Offshore wind In the core MARKAL scenario, rates of installation of offshore wind increase from.7 GW per year to 1.2 GW per year by 225, thereafter levelling off at.9 GW added per year, equalling the replacement rate. This means that offshore wind capacity increases to 18 GW by 23, before remaining approximately constant to 25. As shown in Table 1, this corresponds to a maximum of over 3,1 turbines of size 5.8 MW. Similar rates are seen in the high nuclear and high CCS scenarios, but in the Higher renewables scenario, the installation rate rises to 2.7 GW per year from 225, leading total installed offshore wind capacity to rise to 54 GW by 24 and to be retained at that level to 25. The Market Rules pathway has rates between these two scenarios, with 3 GW of capacity installed by 25, though again with a more even ramp up, reaching 15 GW by 23. Lower rates of installation are seen in the other two transition pathways, only reaching 17 GW of offshore wind by 25 in the Central Co-ordination pathway and 8 GW of offshore wind by 25 in the Thousand Flowers pathway. Turbine technology has developed since the early stages of deployment with the turbine size increasing from 2 MW seen in UK phase 1 offshore deployment to 3.6 MW in the most recent installations. The deployed turbine size is expected to continue to increase with the Beatrice demonstration project installing two 5 MW turbines and 5-7 MW turbines have been seen in other countries demonstration sites. A 1 MW turbine is also being developed ready for deployment in the North East of England (HM Government 21a). The pathways assume that 5.8 MW turbines are available Year Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS or Markal 3.26 Market Rules Central Coordination Thousand Flowers Figure 6.7. Installed capacity (GW) for onshore wind to 25 in the MARKAL, DECC and Transition Pathways 32

33 Offshore Wind Build Rate, MW/Year Year Higher renewables, more energy efficiency Higher nuclear, less energy efficiency Higher CCS or Markal 3.26 Market Rules Central Coordination Thousand Flowers Figure 6.8. Annual build rates (MW/year) for onshore wind to 25 in the MARKAL, DECC and Transition Pathways In order to reach the high level deployment of offshore wind the government is supporting technology innovation and demonstration, supply chain development, access to finance through the Green Investment Bank (DECC, 211), planning and consenting, grid connection, and incentives for investment under the Renewables Obligation (to 217) and contract for difference feed-in tariffs under Electricity Market Reform, expected to be implemented from 214 (DECC, 212) Tidal range and tidal stream Tidal range has the potential to meet 13% of our electricity demand if fully exploited (DECC 211) and is present in all but the DECC nuclear and CCS pathways. The highest deployment is seen in the core MARKAL and Market Rules pathways with around 7.5 GW of tidal range and 5.7 GW of tidal stream installed capacity in 25. The tidal range capacity equates around 31 sites comparable to the 24 MW la Rance site in France, the only significant tidal range site in operation (DECC 211). The use of technology that utilises the tidal range is well established and typically has an estimated lifetime of 12 years, the capital costs would be recouped (DECC 211). 33

34 Tidal Power Build Rate, MW/Year Tidal Power, GW Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher Nuclear or Higher CCS Market Rules Central Coordination or Thousand Flowers Figure 6.9. Installed capacity (GW) for tidal power to 25 in the MARKAL, DECC and Transition Pathways Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher Nuclear or Higher CCS Market Rules Central Coordination or Thousand Flowers Figure 6.1. Annual build rates (MW/year) for tidal power to 25 in the MARKAL, DECC and Transition Pathways The Severn Estuary is seen as one of the premium locations in the world for tidal range but due to the cost, as well as the local environmental impacts, it was decided that Severn tidal barrage would not be required to meet the 22 renewable energy targets, however the project may still be considered in the future (HM Government 21b). 34

35 Wave Power Build Rate, MW/Year Wave Power, GW 6.6. Wave power These are emerging technologies with the UK at the forefront of research and development through the National Renewable Energy Centre, the European Marine Energy Centre and the WaveHub demonstration facility (HM Government 21a). The core MARKAL pathway sees the highest deployment with 9.6 GW of wave energy from over 6,4 turbines and 5.7 GW of tidal stream energy from 2,85 turbines in 25. To achieve commercial deployment of wave and tidal stream, pre-commercial demonstration sites are planned to be deployed between 213 and 215, with commercial deployment following (DECC 211) Analogous to Markal 3.26 Higher renewables, more energy efficiency 4 Higher nuclear or higher CCS Year Market Rules, Central Coordination or Thousand Flowers Figure Installed capacity (GW) for wave power to 25 in the MARKAL, DECC and Transition Pathways Year Analogous to Markal 3.26 Higher renewables, more energy efficiency Higher nuclear or higher CCS Market Rules, Central Coordination or Thousand Flowers 35

36 Figure Annual build rates (MW/year) for wave power to 25 in the MARKAL, DECC and Transition Pathways The government s priority actions for all marine energy systems are managing the risk and costs of RD&D, securing investment for commercial deployment, developing supply chain infrastructure and ensuring planning and consenting Biomass In each of the DECC scenarios, the biomass power station level is fixed at.6 GW capacity in the form of co-fired power stations up to 23 followed by dedicated biomass combustion. Biomass is also present in combined heat and power stations but without clearly defined inputs or capacities. In the Transition Pathways, biomass is largely used in community CHP plant, with around 1 GW of biogas combined heat and power (CHP) co-generation by 25 in the Market Rules and Central Co-ordination pathways, compared to over 52 GW of biogas CHP in the Thousand Flowers pathway. This represents the most significant difference between any of the scenarios. This biogas CHP (community scale and micro-chp) meets around 63% of home and commercial heating demand in the Thousand Flowers pathway, providing 112 TWh of distributed electricity generation. Assuming a low electrical capacity factor of 3% for home and commercial CHP, together with industrial renewable CHP, this corresponds to 52 GW of installed CHP capacity by 25. The availability of the supply of biomass needed to meet this capacity requires further investigation. Until recently, there has been little policy support available for CHP in the UK, but the Renewable Heat Incentive, which has been in place for non-domestic properties from 211 and will be in place for domestic properties from 214, includes support for renewable micro-chp. The UK government is also supporting work in a number of large UK cities to determine the potential for community-scale heat networks. 36

37 7. Greenhouse gas emissions projections for the Transition Pathways This paper seeks to compares the features of the set of transition pathways for a UK low carbon electricity system to 25 (Hammond and Pearson, 213; Foxon, 213) with those of the DECC scenarios for meeting the 8% greenhouse gas emissions reduction target by 25. The previous sections have compared the electricity demand, supply and technology penetration projections between these pathways and scenarios. This section examines the resulting projections for greenhouse gas emissions. As the MARKAL and DECC scenarios achieve an 8% reduction for the whole UK economy, it is difficult to make a direct comparison with the transition pathways that only cover the electricity sector. However, the calculations in the DECC 25 calculator suggest that, for the MARKAL and DECC scenarios to reach the 8% target for the economy as a whole by 25, the remaining CO 2 emissions from fuel combustion need to be almost completely cancelled out by capture and storage of emissions and by presumed negative emissions associated with the use of bioenergy with CCS. All three transition pathways have been evaluated in terms of their life-cycle energy and environmental performance within a wider sustainability framework. An integrated approach was used to assess the impact of these pathways, employing both energy analysis and environmental life-cycle assessment (LCA), applied on a whole systems basis: from cradle-to-gate. This analysis examined and accounted for all upstream and operational activities right through to the point of delivery to the consumer, as described in (Hammond et al., 213). Climate change, measured in greenhouse gas (GHG) emissions (CO 2e ), is one of 18 environmental impacts examined as part of this life-cycle assessment of the UK electricity supply industry (ESI) for these three high electric low carbon futures. All upstream and operational activities have been examined and the resulting GHG emission quantified. Projected whole systems GHG emissions for the UK ESI (both upstream and operational emissions) can be seen here in figure 7.1. Additionally, whole systems GHG emissions per kwh (gco 2e /kwh e) of electricity produced are illustrated in figure 2. Similar trends were seen by (Hammond et al., 213) relating to version 1.1 of the pathways, although with less decarbonisation achieved by 25. These present results relate to most recent version 2.1 of the pathways. 37

38 Figure 7.1- Projected UK 'Whole Systems' GHG Emissions for the Electricity Sector (MtC2e) under the Three Transition pathways [Source: (Hammond G P & O'Grady Á, 213)] Figure 7.2- Projected 'Whole Systems' GHG Emissions per kwh (gco 2e /kwh e ) under all Three Transition Pathways 38

39 Since the UK s 8% emissions reduction target only relates to territorial emissions within the UK, the direct (stack) emissions were also projected for all three pathways. These emissions are the result of direct operational activities only, i.e. fuel burned on site of the power generator. Therefore all upstream activities associated have been excluded, making direct emissions the primary focus. All direct GHG emissions projected for the UK ESI is shown in figure 7.3. While the direct GHG emissions projected per kwh of electricity is shown in figure 7.4. Figure 7.3-Projected UK Direct Emissions from the Electricity Sector (Mt CO 2e ) under the three pathways 39

40 Figure Projected Direct GHG Emissions per kwh (gco 2e /kwh e ) under all Three Transition Pathways Clearly, by comparing figure 7.1 and 7.3, and figure 7.2 and 7.4, it can easily be determined that upstream emissions have a significant impact on the environmental performance of the electricity grid mix in all three pathways. The carbon intensities (gco 2e /kwh e ) of the three pathways are significantly increased when upstream emissions are included, resulting in a third more emissions in 28, and over three times the emissions for thousand flowers pathway in 25. According to this analysis, the UK ESI was estimated to emit 23 million tonnes of GHG emissions in 28 on a whole systems basis. The grid mix has a carbon intensity of 656 gco 2e /kwh e, although again this can be seen to be much lower on an operational basis only. Under the Market Rules pathway, whole systems emissions from the UK ESI are likely to only fall, accounting for upstream emissions, to around 15 gco 2e /kwh e by 25. In contrast, accounting for operational emissions only, GHG emissions are likely to fall to around 37 gco 2e /kwh e by 25. Under the Central Coordination pathway, whole systems emissions from the UK ESI are likely to only fall to around 73 gco 2e /kwh e by 25, whereas, direct emissions were projected to fall to 27gCO 2e /kwh e by 25. The Thousand Flowers pathway was projected to have the lowest emissions, with whole systems GHG emissions of around 53 gco 2e /kwh e by 25, and direct GHG emissions of 12 gco 2e /kwh e by 25. The large discrepancy between these figures is largely due to the dependence of the pathways on coal and gas CCS, and in particular, the high upstream emissions associated with these technologies (Hammond G P & O'Grady Á, 213). The Committee on Climate Change (CCC) has advocated deep cuts in power sector operational emissions through the 22s (CCC, 21), with UK electricity generation largely decarbonised by In contrast, the present transition pathways (see again figure 4